In drilling bore holes in subterranean earth formations by the rotary method, drill bits fitted with one or more cutters are conventionally employed. For example, rolling cutter or “rock bits” that include three rolling cutters or cones may be employed. The drill bit is secured to the lower end of a drill string, which may be rotated from the surface using a rotary table or top drive, from within the bore hole using a downhole motor or turbine, or using a combination of drive systems. The rolling cutters mounted on the drill bit roll and slide on and across the exposed surface of the formation at the bottom of the bore hole as the bit is rotated, crushing and scraping away the formation material. Cutting elements in the form of inserts or integrally formed teeth are provided on the exterior surface of the rolling cutters and the weight-on-bit (WOB) applied thereto forces the cutting elements on the rolling cutters to penetrate and gouge the formation.
During drilling, drilling fluid is pumped down the bore hole through the drill string to the drill bit. The drilling fluid passes through an internal longitudinal bore (or plenum) within the drill bit and through other fluid conduits or passageways within the drill bit to nozzles that direct the drilling fluid out from the drill bit at relatively high velocity. The nozzles may be directed toward the rolling cutters and cutting elements thereon to clean formation cuttings and detritus from the cutters and prevent “balling” of the drill bit. The nozzles also may be directed past the rolling cutters and toward the bottom of the bore hole to flush cuttings and detritus off from the bottom of the bore hole and up the annulus between the drill string and the bore hole wall.
In inclined and horizontal bore holes, the cuttings that are flushed from the bottom of the well bore may gravitate to the lower side of the annulus where they accumulate in a layer or bed of mud and cuttings. The thickness of this cuttings bed may vary depending on the inclination of the bore hole, the rotational speed of the drill bit and the ability of the nozzles and drilling fluid to flush the cuttings. The exterior surfaces of the drill bit must rotate through this bed of abrasive cuttings that can cause the surfaces of the drill bit to wear, and may eventually lead to failure of the drill bit. In addition, the outer surfaces of the drill bit (e.g., the legs of a roller cone drill bit) form a large, smooth bearing surface that, in an inclined bore hole, causes the drill bit to ride up or sit on the cuttings bed. As the bit rides up on the cuttings bed, the entire bit can become wedged between the cuttings bed and the opposing wall of the bore hole, resulting in increased torque and drag against the drill bit surfaces. This increase in torque and drag reduces the power delivered to the drill bit and can, in extreme cases, cause the drill bit to become stuck in the bore hole. Furthermore, formation cuttings that are preferentially extruded through the narrow, open space between the rolling cutters and the bit legs that support them can damage the seals that are positioned between the rolling cutters and the bearing shafts that extend from the bit legs and on which the rolling cutters are mounted.
It is known in the art to apply a layer of hardfacing over portions of the exterior surfaces of the drill bit to protect the bit against abrasive wear. As used herein, the term “hardfacing” means any material or mass of material that is applied to a surface of a separately formed body and that is relatively more resistant to wear (abrasive wear and/or erosive wear) relative to the material of the separately formed body at the surface. Conventional hardfacing includes hard particles, such as sintered, cast, or macrocrystalline tungsten carbide, dispersed in a metal or metal alloy matrix material. Such hardfacing materials are conventionally applied to the surfaces of a drill bit using a flame-spray process or a welding process.
Various attempts have been made to improve the flow of formation cuttings upward in the bore hole and to reduce the accumulation of formation cuttings between the rolling cutters and the bit legs. For example, U.S. Pat. No. 7,182,162 to Beuershausen et al., the disclosure of which patent is incorporated herein in its entirety by this reference, discloses drill bits that are configured to reduce the damaging effects of formation cuttings. However, as the lifespan of rolling cutters and drill bits employing rolling cutters continues to grow, the accumulation of formation cuttings over time can eventually damage the bearing seals between the rolling cutters and the bearing shafts on which they are mounted.